Heat exchanger for a liquefied natural gas facility

ABSTRACT

A method of constructing a plate fin heat exchanger includes joining a first side bar formed from a nickel-iron alloy to a first end of a fin element formed from a nickel-iron alloy through a first nickel-iron alloy bond, and joining a second side bar formed from a nickel-iron alloy to a second end of the fin element through a second nickel-iron alloy bond to create a first layer of the plate fin heat exchanger. The fin element defines a fluid passage.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of and claims the benefit of priorityto U.S. Non-Provisional application Ser. No. 14/633,307 filed on Feb.27, 2015, which claims priority benefit of priority to U.S. ProvisionalPatent Ser. No. 61/947,797 filed on Mar. 4, 2014. Each of theseapplication is incorporated by reference in its entirety herein.

FIELD OF THE INVENTION

This invention relates to systems and processes for liquefying naturalgas. In another aspect, the invention concerns LNG processes andfacilities employing a heavies removal system. In another aspect, theinvention concerns heat integrating feed and compressor dischargestreams with a heavies removal system in an LNG facility.

BACKGROUND OF THE INVENTION

Cryogenic liquefaction is commonly used to convert natural gas into amore convenient form for transportation and/or storage. Becauseliquefying natural gas greatly reduces its specific volume, largequantities of natural gas can be economically transported and/or storedin liquefied form.

Transporting natural gas in its liquefied form can effectively link anatural gas source with a distant market when the source and market arenot connected by a pipeline. This situation commonly arises when thesource of natural gas and the market for the natural gas are separatedby large bodies of water. In such cases, liquefied natural gas (LNG) canbe transported from the source to the market using specially designedocean-going LNG tankers.

Storing natural gas in its liquefied form can help balance periodicfluctuations in natural gas supply and demand. In particular, LNG can be“stockpiled” for use when natural gas demand is low and/or supply ishigh. As a result, future demand peaks can be met with LNG from storage,which can be vaporized as demand requires.

Several methods exist for liquefying natural gas. Some methods produce apressurized LNG (PLNG) product that is useful but requires expensivepressure-containing vessels for storage and transportation. Othermethods produce an LNG product having a pressure at or near atmosphericpressure. In general, these non-pressurized LNG production methodsinvolve cooling a natural gas stream through indirect heat exchange withone or more refrigerants and then expanding the cooled natural gasstream to near atmospheric pressure. In addition, most LNG facilitiesemploy one or more systems to remove contaminants (e.g., water, mercuryand mercury components, acid gases, and nitrogen, as well as a portionof ethane and heavier components) from the natural gas stream atdifferent points during the liquefaction process.

In general, LNG facilities are designed and operated to provide LNG to asingle market in a specific region of the world. Because specificationsfor the final characteristics of the natural gas product, such as, forexample, higher heating value (HHV), Wobbe index, methane content,ethane content, C₃+ content, and inerts content vary widely throughoutthe world, LNG facilities are typically optimized to meet a certain setof specifications for a single market. In large part, achieving thestringent final product specifications involves effectively removingcertain components from the natural gas feed stream. LNG facilities mayemploy one or more distillation columns to remove these components fromthe incoming natural gas stream. Oftentimes, the heavies removal systemis configured in a two column arrangement utilizing a high pressuredemethanizer followed by a lower downstream column. In addition, atleast one of the columns used to separate the heavier components fromthe natural gas stream can generally be operated at or near the criticalpressure of the components being separated. These limitations, coupledwith rigid product specifications, results in distillation columns thatare typically designed to operate within a relatively narrow range ofconditions. When situations arise that force the columns out of designrange (e.g., start-up of the facility or fluctuations in feedcomposition), the resulting column operation may result in product lossand/or a LNG product that does not meet the desired productspecifications.

Gas treatment facilities, such as systems that process cryogenic gases,liquids, and/or two-phase mixtures including, but not limited to, liquidnatural gas (LNG), employ heat exchangers to condition various fluidflows. One or more fluid streams (which may or may not include differenttypes of fluids) are passed through layers each having fins that extendbetween side bars. Adjacent process layers are separated by a partingsheet. One or more hot process fluids are passed over the fins tosimultaneously exchange heat with one or more cold process fluidstreams. The one or more fluid streams exchange heat to achieve adesired temperature. Currently, plate fin heat exchangers areconstructed using aluminum. Aluminum is a relatively light weightmaterial and possesses desirable heat exchange properties. However,aluminum possesses very poor mechanical strength and fatigue-resistanceproperties. In plate fin heat exchangers constructed using aluminum,components are typically joined through brazed joints and/orconnections.

SUMMARY OF THE INVENTION

In accordance with an exemplary embodiment, a method of constructing aplate fin heat exchanger includes joining a first side bar formed from anickel-iron alloy to a first end of a fin element formed from anickel-iron alloy through a first nickel-iron alloy bond and joining asecond side bar formed from a nickel-iron alloy to a second end of thefin element through a second nickel-iron alloy bond to create a firstlayer of the plate fin heat exchanger. The fin element defines a fluidpassage.

In accordance with an aspect of an exemplary embodiment, a cryogenic gasprocessing system includes a chiller, and a low temperature separator(LTS) including an inlet fluidically connected to the chiller, a firstoutlet and a second outlet. A flash drum includes an inlet fluidicallyconnected to the LTS and a plurality of outlets. A heat exchanger isfluidically connected to the second outlet of the LTS and the pluralityof outlets of the flash drum. The heat exchanger includes a first sidebar formed from a nickel-iron alloy and a second side bar formed from anickel-iron alloy. The second side bar is spaced from the first sidebar. A fin element formed from a nickel-iron alloy extends between thefirst side bar and the second side bar forming a first layer of the heatexchanger. The fin element includes an inner passage and is formed froma nickel-iron alloy. A first nickel-iron alloy bond joins the finelement and the first side bar, and a second nickel-iron alloy bondjoins the fin element and the second side bar.

In accordance with another aspect of an exemplary embodiment, a heatexchanger includes a first side bar formed from a nickel-iron alloy anda second side bar formed from a nickel-iron alloy. The second side baris spaced from the first side bar. A fin element formed from anickel-iron alloy extends between the first side bar and the second sidebar forming a first layer of the heat exchanger. The fin elementincludes an inner passage and is formed from a nickel-iron alloy. Afirst nickel-iron alloy bond joins the fin element and the first sidebar, and a second nickel-iron alloy bond joins the fin element and thesecond side bar.

A hybrid core-in-shell heat exchanger includes a vessel having aninterior portion configured to receive a refrigerant. A first exchangerhaving a first exchanger configuration is arranged in the interiorportion. A second exchanger having a second exchanger configuration isarranged in the interior portion and is fluidically isolated from thefirst exchanger, the second exchanger configuration being distinct fromthe first exchanger configuration.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention, together with further advantages thereof, may best beunderstood by reference to the following description taken inconjunction with the accompanying figures by way of example and not byway of limitation, in which:

FIG. 1 is a simplified overview of a cascade-type LNG facilityconfigured in accordance with one embodiment of the present invention;

FIG. 2 is a schematic diagram of a cascade-type LNG facility configuredin accordance with one embodiment of present invention with certainportions of the LNG facility connecting to lines A, B, C, D, E and/or Fbeing illustrated in FIG. 1;

FIG. 3 is a schematic diagram illustrating one embodiment of a heaviesremoval zone integrated into the LNG facility of FIG. 1 through lines A,B, C, D, E and/or F;

FIG. 4 depicts a schematic diagram of a portion of the cascade-type LNGfacility including a plate fin heat exchanger formed from a nickel-ironalloy material, in accordance with an exemplary embodiment;

FIG. 5 is a partially cut-away perspective view of the plate fin heatexchanger formed from the nickel-iron alloy material of FIG. 4;

FIG. 6 depicts a disassembled view illustrating various components ofthe plate fin heat exchanger of FIG. 5;

FIG. 7 depicts an assembled view of the plate fin heat exchanger of FIG.6; and

FIG. 8 depicts a hybrid core-in-shell heat exchanger, in accordance withyet another aspect of an exemplary embodiment.

DETAILED DESCRIPTION OF THE INVENTION

Reference will now be made in detail to embodiments of the invention,one or more examples of which are illustrated in the accompanyingdrawings. Each example is provided by way of explanation of theinvention, not as a limitation of the invention. It will be apparent tothose skilled in the art that various modifications and variations canbe made in the present invention without departing from the scope orspirit of the invention. For instance, features illustrated or describedas part of one embodiment can be used on another embodiment to yield astill further embodiment. Thus, it is intended that the presentinvention cover such modifications and variations that come within thescope of the appended claims and their equivalents.

The present invention can be implemented in a facility used to coolnatural gas to its liquefaction temperature to thereby produce liquefiednatural gas (LNG). The LNG facility generally employs one or morerefrigerants to extract heat from the natural gas and reject theenvironment. Numerous configurations of LNG systems exist and thepresent invention may be implemented in many different types of LNGsystems.

In one embodiment, the present invention can be implemented in a mixedrefrigerant LNG system. Examples of mixed refrigerant processes caninclude, but are not limited to, a single refrigeration system using amixed refrigerant, a propane pre-cooled mixed refrigerant system, and adual mixed refrigerant system.

In another embodiment, the present invention is implemented in a cascadeLNG system employing a cascade-type refrigeration process using one ormore predominately pure component refrigerants. The refrigerantsutilized in cascade-type refrigeration processes can have successivelylower boiling points in order to facilitate heat removal from thenatural gas stream being liquefied. Additionally, cascade-typerefrigeration processes can include some level of heat integration. Forexample, a cascade-type refrigeration process can cool one or morerefrigerants having a higher volatility through indirect heat exchangewith one or more refrigerants having a lower volatility. In addition tocooling the natural gas stream through indirect heat exchange with oneor more refrigerants, cascade and mixed-refrigerant LNG systems canemploy one or more expansion cooling stages to simultaneously cool theLNG while reducing its pressure.

Referring now to FIG. 1, one embodiment of a cascade-type LNG facility,in accordance with one embodiment of the present invention, isillustrated. The LNG facility depicted in FIG. 1 generally comprises apropane refrigeration cycle 30, an ethylene refrigeration cycle 50, anda methane refrigeration cycle 70 with an expansion section 80. FIGS. 2and 3 illustrate embodiments of heavies removal zones capable of beingintegrated into the LNG facility depicted in FIG. 1. While “propane”,“ethylene”, and “methane” are used to refer to respective first, second,and third refrigerants, it should be understood that the embodimentillustrated in FIG. 1 and described herein can apply to any combinationof suitable refrigerants. The main components of propane refrigerationcycle 30 include a propane compressor 31, a propane cooler/condenser 32,high-stage propane chillers 33A and 33B, an intermediate-stage propanechiller 34, and a low-stage propane chiller 35. The main components ofethylene refrigeration cycle 50 include an ethylene compressor 51, anethylene cooler 52, a high-stage ethylene chiller 53, a low-stageethylene chiller/condenser 55, and an ethylene economizer 56. The maincomponents of methane refrigeration cycle 70 include a methanecompressor 71, a methane cooler 72, and a methane economizer 73. Themain components of expansion section 80 include a high-stage methaneexpansion valve and/or expander 81, a high-stage methane flash drum 82,an intermediate-stage methane expansion valve and/or expander 83, anintermediate-stage methane flash drum 84, a low-stage methane expansionvalve and/or expander 85, and a low-stage methane flash drum 86. FIGS. 2and 3 present embodiments of a heavies removal zone that is integratedinto the LNG facility depicted in FIG. 1 through lines A-F.

The operation of the LNG facility illustrated in FIG. 1 will now bedescribed in more detail, beginning with propane refrigeration cycle 30.Propane is compressed in multi-stage (e.g., three-stage) propanecompressor 31 driven by, for example, a gas turbine driver (notillustrated). The stages of compression may exist in a single unit ortwo or more separate units mechanically coupled to a single driver. Uponcompression, the propane is passed through conduit 300 to propane cooler32, wherein it is cooled and liquefied through indirect heat exchangewith an external fluid (e.g., air or water). The stream from propanecooler 32 can then be passed through conduit 302 to a pressure reductionmeans, illustrated as expansion valve 36A, wherein the pressure of theliquefied propane is reduced, thereby evaporating or flashing a portionthereof. The resulting two-phase stream then flows through conduit 304 ainto high-stage propane chiller 33 a. High stage propane chiller 33 auses the flashed propane refrigerant to cool the incoming natural gasstream in conduit 110.

The cooled natural gas stream from high-stage propane chiller 33 a flowsthrough conduit 114 to a separation vessel (not shown), wherein waterand, in some cases, propane and heavier components are removed,typically followed by a treatment system 40, when not already completedin upstream processing, wherein moisture, mercury and mercury compounds,particulates, and other contaminants are removed to create a treatedstream. The stream exits the treatment system 40 through conduit 116.Thereafter, a portion of the stream in conduit 116 can be routed throughconduit A to a heavies removal zone illustrated in FIG. 2 or 3, whichwill be discussed in detail shortly. The remaining portion of the streamin conduit 116 is combined with a yet-to-be discussed stream in conduitG exiting the heavies removal zone illustrated. The combined stream canthen enter intermediate-stage propane chiller 34, wherein the stream iscooled in indirect heat exchange means 41 through indirect heat exchangewith a yet-to-be-discussed propane refrigerant stream. The resultingcooled stream in conduit 118 can then be recombined with ayet-to-be-discussed stream in conduit B exiting heavies removal zoneillustrated in FIG. 2 or 3, and the combined stream can then be routedto low-stage propane chiller 35, wherein the stream can be furthercooled through indirect heat exchange means 42. The resulting cooledstream can then exit low-stage propane chiller 35 through conduit 120.Subsequently, the cooled stream in conduit 120 can be routed tohigh-stage ethylene chiller 53, which will be discussed in more detailshortly.

The combined vaporized propane refrigerant stream exiting high-stagepropane chillers 33A and 33B is returned to the high-stage inlet port(not separately labeled) of propane compressor 31 through conduit 306.The liquid propane refrigerant in high-stage propane chiller 33Aprovides refrigeration duty for the natural gas stream. Two-phaserefrigerant stream can enter the intermediate-stage propane chiller 34through conduit 310, thereby providing coolant for the natural gasstream (in conduit 116) and to yet-to-be-discussed streams enteringintermediate-stage propane chiller 34 through conduits 204 and 310. Thevaporized portion of the propane refrigerant exits intermediate-stagepropane chiller 34 through conduit 312 and can then enter theintermediate-stage inlet port (not separately labeled) of propanecompressor 31. The liquefied portion of the propane refrigerant exitsintermediate-stage propane chiller 34 through conduit 314 and is passedthrough a pressure-reduction means, illustrated here as expansion valve44, whereupon the pressure of the liquefied propane refrigerant isreduced to thereby flash or vaporize a portion thereof. The resultingvapor-liquid refrigerant stream can then be routed to low-stage propanechiller 35 through conduit 316 and where the refrigerant stream can coolthe methane-rich stream and a yet-to-be-discussed ethylene refrigerantstream entering low-stage propane chiller 35 through conduits 118 and206, respectively. The vaporized propane refrigerant stream then exitslow-stage propane chiller 35 and is routed to the low-stage inlet portof propane compressor 31 through conduit 318 wherein it is compressedand recycled as previously described.

As shown in FIG. 1, a stream of ethylene refrigerant in conduit 202enters high-stage propane chiller 33 b, wherein the ethylene stream iscooled through indirect heat exchange means 39. The resulting cooledethylene stream can then be routed in conduit 204 from high-stagepropane chiller 33 b to intermediate-stage propane chiller 34. Uponentering intermediate-stage propane chiller 34, the ethylene refrigerantstream can be further cooled through indirect heat exchange means 45 inintermediate-stage propane chiller 34. The resulting cooled ethylenestream can then exit intermediate-stage propane chiller 34 and can berouted through conduit 206 to enter low-stage propane chiller 35. Inlow-stage propane chiller 35, the ethylene refrigerant stream can be atleast partially condensed, or condensed in its entirety, throughindirect heat exchange means 46. The resulting stream exits low-stagepropane chiller 35 through conduit 208 and can subsequently be routed toa separation vessel 47, wherein a vapor portion of the stream, ifpresent, can be removed through conduit 210, while a liquid portion ofthe ethylene refrigerant stream can exit separation vessel 47 throughconduit 212. The liquid portion of the ethylene refrigerant streamexiting separation vessel 47 can have a representative temperature andpressure of about −24° F. (about −31° C.) and about 285 psia (about1,965 kPa).

Turning now to ethylene refrigeration cycle 50 in FIG. 1, the liquefiedethylene refrigerant stream in conduit 212 can enter ethylene economizer56, wherein the stream can be further cooled by an indirect heatexchange means 57. The resulting cooled liquid ethylene stream inconduit 214 can then be routed through a pressure reduction means,illustrated here as expansion valve 58, whereupon the pressure of thecooled predominantly liquid ethylene stream is reduced to thereby flashor vaporize a portion thereof. The cooled, two-phase stream in conduit215 can then enter high-stage ethylene chiller 53. In high-stageethylene chiller 53, at least a portion of the ethylene refrigerantstream can vaporize to further cool the stream in conduit 121 enteringan indirect heat exchange means 59. The vaporized and remainingliquefied ethylene refrigerant exits high-stage ethylene chiller 53through respective conduits 216 and 220. The vaporized ethylenerefrigerant in conduit 216 can re-enter ethylene economizer 56, whereinthe stream can be warmed through an indirect heat exchange means 60prior to entering the high-stage inlet port of ethylene compressor 51through conduit 218, as shown in FIG. 1.

The cooled stream in conduit 120 exiting low-stage propane chiller 35can thereafter be split into two portions, as shown in FIG. 1. At leasta portion of the natural gas stream can be routed through conduit E.While the remaining portion of the cooled natural gas stream in conduit121 can be routed to high-stage ethylene chiller 53, and then can be andcooled in indirect heat exchange means 59 of high-stage ethylene chiller53.

The remaining liquefied ethylene refrigerant exiting high-stage ethylenechiller 53 in conduit 220 can re-enter ethylene economizer 56, to befurther sub-cooled by an indirect heat exchange means 61 in ethyleneeconomizer 56. The resulting sub-cooled refrigerant stream exitsethylene economizer 56 through conduit 222 and can subsequently berouted to a pressure reduction means, illustrated here as expansionvalve 62, whereupon the pressure of the refrigerant stream is reduced tothereby vaporize or flash a portion thereof. The resulting, cooledtwo-phase stream in conduit 224 enters low-stage ethylenechiller/condenser 55.

As shown in FIG. 1, a portion of the cooled natural gas stream exitinghigh-stage ethylene chiller 53 can be routed through conduit C to theheavies removal zone in FIG. 2 or 3 through conduit C, while anotherportion of the cooled natural gas stream exiting high-stage ethylenechiller 53 can be routed through conduit 122 to enter indirect heatexchange means 63 of low-stage ethylene chiller/condenser 55. Theremaining portion of the cooled natural gas stream in conduit 122 canthen be combined in the first column vapor stream exiting the heaviesremoval zone (e.g. first column vapor stream exiting the firstdistillation column 650 in FIG. 2 or 3 through the overheat outlet) inconduit D and/or may be combined with a yet-to-be-discussed streamexiting methane refrigeration cycle 70 in conduit 168, for the resultingcomposite stream to then enter indirect heat exchange means 63 inlow-stage ethylene chiller/condenser 55, as shown in FIG. 1.

In low-stage ethylene chiller/condenser 55, the cooled stream (which cancomprise the stream in conduit 122 optionally combined with streams inconduits D and 168) can be at least partially condensed through indirectheat exchange with the ethylene refrigerant entering low-stage ethylenechiller/condenser 55 through conduit 224. The vaporized ethylenerefrigerant exits low-stage ethylene chiller/condenser 55 throughconduit 226 and can then enter ethylene economizer 56. In ethyleneeconomizer 56, the vaporized ethylene refrigerant stream can be warmedthrough an indirect heat exchange means 64 prior to being fed into thelow-stage inlet port of ethylene compressor 51 through conduit 230. Asshown in FIG. 1, a stream of compressed ethylene refrigerant exitsethylene compressor 51 through conduit 236 and can subsequently berouted to ethylene cooler 52, wherein the compressed ethylene stream canbe cooled through indirect heat exchange with an external fluid (e.g.,water or air). The resulting cooled ethylene stream can then beintroduced through conduit 202 into high-stage propane chiller 33B foradditional cooling as previously described.

The cooled natural gas stream exiting low-stage ethylenechiller/condenser 55 in conduit 124 can also be referred to as the“pressurized LNG-bearing stream”. As shown in FIG. 1, the pressurizedLNG-bearing stream exits low-stage ethylene chiller/condenser 55 throughconduit 124 prior to entering main methane economizer 73. In mainmethane economizer 73, the methane-rich stream in conduit 124 can becooled in an indirect heat exchange means 75 through indirect heatexchange with one or more yet-to-be discussed methane refrigerantstreams. The cooled, pressurized LNG-bearing stream exits main methaneeconomizer 73 through conduit 134 and can then be routed into expansionsection 80 of methane refrigeration cycle 70. In expansion section 80,the pressurized LNG-bearing stream first passes through high-stagemethane expansion valve 81 and/or expander, whereupon the pressure ofthis stream is reduced to thereby vaporize or flash a portion thereof.The resulting two-phase methane-rich stream in conduit 136 can thenenter high-stage methane flash drum 82, whereupon the vapor and liquidportions of the reduced-pressure stream can be separated. The vaporportion of the reduced-pressure stream (also called the high-stage flashgas) exits high-stage methane flash drum 82 through conduit 138 to thenenter main methane economizer 73, wherein at least a portion of thehigh-stage flash gas can be heated through indirect heat exchange means76 of main methane economizer 73. The resulting warmed vapor streamexits main methane economizer 73 through conduit 138 and can then berouted to the high-stage inlet port of methane compressor 71, as shownin FIG. 1.

The liquid portion of the reduced-pressure stream exits high-stagemethane flash drum 82 through conduit 142 to then re-enter main methaneeconomizer 73, wherein the liquid stream can be cooled through indirectheat exchange means 74 of main methane economizer 73. The resultingcooled stream exits main methane economizer 73 through conduit 144 andcan then be routed to a second expansion stage, illustrated here asintermediate-stage expansion valve 83, but could include an expander.Intermediate-stage expansion valve 83 further reduces the pressure ofthe cooled methane stream which reduces the stream's temperature byvaporizing or flashing a portion thereof. The resulting two-phasemethane-rich stream in conduit 146 can then enter intermediate-stagemethane flash drum 84, wherein the liquid and vapor portions of thisstream can be separated and can exit the intermediate-stage flash drum84 through respective conduits 148 and 150. The vapor portion (alsocalled the intermediate-stage flash gas) in conduit 150 can re-entermethane economizer 73, wherein the vapor portion can be heated throughan indirect heat exchange means 77 of main methane economizer 73. Theresulting warmed stream can then be routed through conduit 154 to theintermediate-stage inlet port of methane compressor 71, as shown in FIG.1.

The liquid stream exiting intermediate-stage methane flash drum 84through conduit 148 can then pass through a low-stage expansion valve 85and/or expander, whereupon the pressure of the liquefied methane-richstream can be further reduced to thereby vaporize or flash a portionthereof. The resulting cooled, two-phase stream in conduit 156 can thenenter low-stage methane flash drum 86, wherein the vapor and liquidphases can be separated. The liquid stream exiting low-stage methaneflash drum 86 through conduit 158 can comprise the liquefied natural gas(LNG) product. The LNG product, which is at about atmospheric pressure,can be routed through conduit 158 downstream for subsequent storage,transportation, and/or use.

The vapor stream exiting low-stage methane flash drum (also called thelow-stage methane flash gas) in conduit 160 can be routed to methaneeconomizer 73, wherein the low-stage methane flash gas can be warmedthrough an indirect heat exchange means 78 of main methane economizer73. The resulting stream can exit methane economizer 73 through conduit164, whereafter the stream can be routed to the low-stage inlet port ofmethane compressor 71.

Methane compressor 71 can comprise one or more compression stages. Inone embodiment, methane compressor 71 comprises three compression stagesin a single module. In another embodiment, one or more of thecompression modules can be separate, but can be mechanically coupled toa common driver. Generally, one or more intercoolers (not shown) can beprovided between subsequent compression stages.

As shown in FIG. 1, the compressed methane refrigerant stream exitingmethane compressor 71 can be discharged into conduit 166. A portion ofthe compressed methane refrigerant stream exiting compressor 71 throughconduit 166 can be routed through conduit F to the heavies removal zonesin FIGS. 2 and 3 through conduit F, while another portion of thecompressed methane refrigerant can be routed to methane cooler 72,whereafter the stream can be cooled through indirect heat exchange withan external fluid (e.g., air or water) in methane cooler 72. Theresulting cooled methane refrigerant stream exits methane cooler 72through conduit 112, whereafter a portion of the methane refrigerant canbe routed through conduit H to the heavies removal zones in FIG. 2,while the remaining portion of the methane refrigerant stream can bedirected to and further cooled in propane refrigeration cycle 30.

Upon being cooled in propane refrigeration cycle 30 through heatexchanger means 37, the methane refrigerant stream can be dischargedinto conduit 130 and subsequently routed to main methane economizer 73,wherein the stream can be further cooled through indirect heat exchangemeans 79. The resulting sub-cooled stream exits main methane economizer73 through conduit 168 and can then combined with stream in conduit 122exiting high-stage ethylene chiller 53 and/or with stream in conduit Dexiting the heavies removal zone (e.g. first predominately vapor streamfrom first distillation column 650 in FIGS. 2-3) prior to enteringlow-stage ethylene chiller/condenser 55, as previously discussed.

Turning now to FIG. 2, one embodiment of a heavies removal zone suitablefor integration with the LNG facility depicted in FIG. 1 is illustrated.The heavies removal zone depicted in FIG. 2 generally comprises: a firstdistillation column 650, a first heat exchanger or reboiler 654, a valve644 and/or an expander, a second heat exchanger 750, a seconddistillation column 660, and a third heat exchanger 652. The streamsexiting the LNG facility depicted in FIG. 1 and routed to the heaviesremoval zone are dependent upon the operating conditions of the heaviesremoval zone, i.e., the temperature, pressure, etc. Likewise, uponexiting the heavies removal zone several streams are reintroduced intothe LNG facility depicted in FIG. 1 at an appropriate stage in theprocess to facilitate thermal design and not to damage the equipment. Inone embodiment, the streams returning to the LNG facility depicted inFIG. 1 are reintroduced through manual or automated sequencing valves tothereby deliver the incoming fluid to the appropriate stages within theequipment limitations.

In an embodiment as shown in FIG. 1, a cooled natural gas stream exitingdownstream of the high-stage ethylene chiller 53 through conduit C iscombined with a predominantly vapor stream exiting downstream oflow-stage propane chiller 35 through conduit E in FIG. 1 (a portion of anatural gas stream) and enters the heavies removal zones shown in FIGS.2 and 3. In FIG. 2, the combined stream in conduits C and E enter acontrol valve 644 and/or an expander and is subsequently introduceddirectly into first distillation column 650 through conduit 601. Thecontrol valve adjusts pressure or flow. In an embodiment, an analyzer(not shown) monitors and controls the temperature of the incomingcombined D and E streams and adjusts the relative stream flow rates tothereby adjust the first distillation column inlet temperature asnecessary to help control the desired separation.

Referring to FIG. 2, the first distillation column 650 separates theincoming streams producing a first column vapor stream, a first columnliquid bottoms stream and a reboiler cold side inlet stream. The firstdistillation column contains a chimney or trap-out tray (not shown),wherein lighter composition streams are directed to the upper regions ofthe distillation column while heavier composition streams are routed tothe lower portions of the distillation column. A first column vaporstream can be withdrawn from an overhead vapor outlet of firstdistillation column and thereafter be routed through conduit D to theliquefaction process of the LNG facility depicted in FIG. 1. The firstcolumn liquid bottoms stream can be withdrawn from a bottom outlet offirst distillation column 650 and can thereafter be routed throughconduit 602 to a second heat exchanger 750, discussed below. Thereboiler inlet stream exits the distillation column at the chimney ortrap-out tray and is routed through conduit 604 to the first reboiler654, discussed below.

Referring now to FIG. 2, at least a portion of the natural gas streamwithdrawn from conduit 116 in FIG. 1 can be routed to the heaviesremoval zones depicted in FIG. 2 through conduit A. In an embodiment,the at least a portion of the natural gas stream withdrawn from conduit116 in FIG. 1 is a treated natural gas feed stream. As shown in FIG. 2,the stream in conduit A can enter the warm fluid inlet of first reboiler654 to form a heating pass 680 and thereby provide reboiler heat duty tothe first distillation column 650. The portion of the natural gas streamprovides heat duty to at least a portion of the reboiler cold side inletstream to thereby produce, in a cooled and in some cases a partiallycondensed portion of the natural gas stream, a first heated liquidfraction 608(a) and a first heated vapor fraction 608(b). The cooledand/or partially condensed portion of the natural gas stream iswithdrawn from the warm side outlet of the first reboiler 654 and cansubsequently be routed back into the LNG facility through conduit B. Inan embodiment the flow of treated natural gas supplied to the warm sideinlet may be adjusted to control temperature at an optimal location onthe first distillation column or peripheral equipment piping.

As shown in FIG. 1, a portion of the natural gas stream exiting a highstage methane compressor through conduit 166 can be withdrawn throughconduits H or F and can be routed to the heavies removal zones depictedin FIG. 2 or 3. In an embodiment, the portion of the natural gas streamin conduits H or F in FIG. 1 is a methane compressor discharge stream.As shown in FIG. 2, the portion of the natural gas stream in conduits Hor F can enter the warm fluid inlet of a cooling pass 582 of second heatexchanger 750 to thereby provide heat duty to the second heat exchanger750. The portion of the natural gas stream along with a portion of thefirst column liquid bottoms stream undergo indirect heat exchange tothereby produce a cooled portion of the natural gas stream and a secondheated stream. The resulting cooled portion of the natural gas streamwithdrawn from the warm side outlet of the second heat exchanger 750 cansubsequently be routed back to the LNG facility through conduit G. Thesecond heated stream withdrawn from the second heat exchanger 750through conduit 610 can be introduced into a feed inlet of seconddistillation column 660. In one embodiment, the second heat exchanger750 is used as an LNG stabilizer feed heater with the warm side fluidinlet flow rate through conduit H or F or warm side fluid outlet flowrate through conduit G controlled to produce an optimal seconddistillation column feed temperature.

The second distillation column 660 separates the incoming streams. Asecond column overhead vapor stream (also called “second overheadstream”) is withdrawn through conduit 622 from second distillationcolumn 660. A portion of the second column overhead vapor stream exitingsecond distillation column 660 can enter cooling pass 684 of third heatexchanger 652, wherein the stream can be cooled and at least partiallycondensed using air, water, or other suitable coolant. The resultingcondensed or two-phase stream can then be routed through conduit 624 toa reflux accumulator 664, wherein the stream can be separated into avapor and liquid phase.

Turning now to FIG. 3, another embodiment of a heavies removal zonesuitable for integration with the LNG facility depicted in FIG. 1 isillustrated. The heavies removal zone depicted in FIG. 3 generallycomprises: a first distillation column 650, a first heat exchanger orreboiler 654, a feed separator 644, an expansion device 646, a secondheat exchanger 750, a second distillation column 660, an optional vaporliquid separator 653, and a third heat exchanger 652. The streamsexiting the LNG facility depicted in FIG. 1 and routed to the heaviesremoval zone are dependent upon the operating conditions of the heaviesremoval zone, i.e., the temperature, pressure, etc. Likewise, uponexiting the heavies removal zone several streams are reintroduced intothe LNG facility depicted in FIG. 1 at an appropriate stage in theprocess as not to damage the equipment. In one embodiment, the streamsreturning to the LNG facility depicted in FIG. 1 are reintroducedthrough manual or automated sequencing valves to thereby deliver theincoming fluid to the appropriate stages within the equipmentlimitations.

In FIG. 3, the combined streams of conduits C and E can be introducedinto a feed separator 644, wherein the vapor and liquid phases areseparated thereby producing a vapor fraction and a liquid fraction. Thevapor fraction is introduced into an expansion valve or expander 646 andsubsequently introduced into the first distillation column 650 throughconduit 601(b). The liquid fraction is introduced into the same or lowerlocation of the first distillation column 650 through conduit 603. Byutilizing the feed separator 644, the relatively heavier componentscontained within the liquid stream may be routed to a more optimal feedlocation to the first distillation column 650.

Referring to FIG. 3, the first distillation column 650 separates theincoming streams producing a first column vapor stream, and a firstcolumn liquid bottoms stream. The first column vapor stream can bewithdrawn from the first distillation column 650 through conduit D androuted to the LNG facility as depicted in FIG. 1. The first columnliquid bottoms stream can be withdrawn from a bottom outlet of firstdistillation column 650 and routed through conduit 602 to a second heatexchanger 750, discussed below.

Referring to FIG. 3, the first distillation column 650 can contain achimney or trap-out tray (not shown), wherein column liquids are removedand directed through the third heat exchanger 652 to provide condensingor partial condensing duty before routing to an optional second vaporliquid separator 653. Liquid from the optional second vapor liquidseparator 653 can be routed through conduit 604(b) to the cold sideinlet of the first reboiler 654. Vapor from the optional vapor liquidseparator 653 can be combined with vapor from the first reboiler 654 andreturned to the first distillation column 650 above or below the chimneyor trap-out tray. Liquid from the first reboiler 654 can be returned tothe first distillation column or combined with the first column 650liquid bottoms stream.

Referring now to FIG. 3, at least a portion of the natural gas streamwithdrawn from conduit 116 in FIG. 1 can be routed to the heaviesremoval zones depicted in FIG. 3 through conduit A. As shown in FIG. 3,the stream in conduit A can enter the warm side inlet of the firstreboiler 654 to provide reboiler heat duty to the first distillationcolumn 650. The warm side outlet of the first reboiler 654 exits throughconduit B and is returned to the LNG facility as shown in FIG. 1.

As shown in FIG. 1, a portion of the natural gas stream exiting ahigh-stage methane compressor through conduit 166 can be withdrawnthrough conduits H or F and can be routed to the heavies removal zonesdepicted in FIGS. 2 and 3. In an embodiment, the portion of the naturalgas stream in conduits H or F in FIG. 1 is a methane compressordischarge stream. As shown in FIG. 3, the portion of the natural gasstream in conduits H or F can enter the warm side inlet of the secondheat exchanger 750 to heat cold side inlet stream, which is the firstcolumn liquid bottoms stream in conduit 602, to thereby establish thecold side outlet stream in conduit 610 of the second heat exchanger 750to the optimal or desired feed temperature for the second distillationcolumn 660. The warm side outlet from the second heat exchanger 750 canbe routed back to the LNG facility through conduit G.

Referring to FIG. 3, the second distillation column 660 separates theincoming stream in conduit 610 into a second column overhead vaporstream and second column liquid bottoms stream. The second columnoverhead vapor stream (also called “second overhead stream”) iswithdrawn through conduit 622 from second distillation column 660. Aportion of the second column overhead vapor stream exiting seconddistillation column 660 can enter cooling pass 684 of the third heatexchanger 652, wherein the stream can be cooled and at least partiallycondensed. The resulting cooled and at least partially condensed streamcan then be routed through conduit 624 to a first reflux accumulator664, wherein the stream can be separated into vapor stream 630 andliquid stream 626.

In accordance with an aspect of an exemplary embodiment, the LNGfacility may include a cryogenic gas processing system, generallyindicated at 702, in FIG. 4. Cryogenic gas processing system 702includes a feed gas inlet 704 that is fluidically connected to an inlet705 of a heat exchanger 706 through a valve 708. Heat exchanger 706includes an outlet 710 that is fluidically connected to an inlet 713 ofa chiller 717. Chiller 717 raises a temperature of a feed gas passingfrom heat exchanger 706 and includes an outlet 719 that is fluidicallyconnected to an inlet 724 of a low temperature separator (LTS) 728. LTS728 includes a first outlet 732 and a second outlet 734. First outlet732 is fluidically connected to an inlet 736 of a flash drum 737 througha valve 739. Flash drum 737 includes a first outlet 742 and a secondoutlet 744. First and second outlets 742 and 744 are fluidicallyconnected to second heat exchanger 750 through a plurality of conduits753.

Second heat exchanger 750 includes a first section 760 fluidicallyconnected to chiller 717, a second section 762 fluidically connected toflash drum 737, and a third section 764 fluidically connected to LTS728. More specifically, first section 760 includes an inlet 767fluidically connected to feed gas inlet 704 through a valve (notseparately labeled) and an outlet 768 fluidically connected to inlet 713of chiller 717. Second section 762 includes a first inlet 770 and asecond inlet 771 fluidically connected to flash drum 737. Second section762 also includes a first outlet 772 and a second outlet 773 fluidicallyconnected to another process component (not shown). Third section 764includes an inlet 780 fluidically connected to LTS 728 through a pump782 and an outlet 784 fluidically connected to another process component(also not shown).

Reference will now follow to FIG. 5 in describing second section 762with an understanding that first section 760 and third section 764 mayinclude similar structure. Second section 762 includes a first heatexchange portion 787 and a second heat exchange portion 788. First heatexchange portion 787 includes a first inlet plenum 790 fluidicallyconnected to first inlet 770, and second heat exchange portion 788includes a second inlet plenum 791 fluidically connected to second inlet771. First heat exchange portion 787 also includes a first outlet plenum794 fluidically connected to first outlet 772, and second heat exchangeportion 788 includes a second outlet plenum 795 fluidically connected tosecond outlet 773. First and second heat exchange portions 787 and 788may receive cryogenic fluids and/or gases at similar temperatures or mayreceive cryogenic gases at different temperatures. Second section 762also includes a conditioning flow inlet plenum 798 and a conditioningflow outlet plenum 800. Conditioning flow inlet plenum 798 includes aconditioning flow inlet 804, and conditioning flow outlet plenum 800includes a conditioning flow outlet 806. Conditioning flow inlet plenum798 receives a flow of conditioning fluid that is passed over layers 812that form second section 762. The conditioning fluid exchanges heat witha cryogenic gas passing through layers 812.

As best shown in FIGS. 6 and 7, each layer 812 includes a first side bar820 and a second side bar 822. In the exemplary embodiment shown, firstand second side bars 820 and 822 take the form of first and secondspacers 823 and 824. It should however be understood, that first andsecond side bars 820 and 822 may take on other forms such as fluidplenums, support structures, and the like. A fin element 825 extendsbetween first and second side bars 820 and 822. Fin element 825 extendsfrom a first end 826 to a second end 828 through an intermediate portion830. Intermediate portion 830 includes an inner passage 834 and isformed with a number of bend portions (not separately labeled) that mayinclude a wide array of geometric patterns. Intermediate portion 830provides an enhanced surface area of fin element 825 to increase heattransfer with the conditioning fluid.

A first parting sheet 840 extends between first and second side bars 820and 822 on a first side (not separately labeled) of fin element 825 toform a first layer 841. A second parting sheet 842, which is part of asecond layer 843, extends between first and second side bars 820 and 822on a second, opposing side of fin element 825. First parting sheet 840extends from a first end section 845 to a second end section 846.Similarly, second parting sheet 842 extends from a first end section 848to a second end section 849. First and second side bars 820 and 822 andfirst and second parting sheets 840 and 842 define a conditioning fluidpassage 854 along which extends fin element 825. As will be discussedmore fully below, first and second side bars 820 and 822, parting sheets840 and 842 and fin element 825 are joined, together with second layer843, as well as additional layers 812, to form second section 762. Oncejoined, first and second end plates 858 and 859 are secured to a firstside (not separately labeled) of second section 762 and third and fourthend plates 862 and 863 are joined to a second side (also not separatelylabeled) of second section 762.

In accordance with an exemplary embodiment, second heat exchanger 750 isformed from a nickel-iron alloy. In accordance with an aspect of theexemplary embodiment, the nickel-iron alloy includes a nickel content ofbetween about 32% and about 42%. In accordance with another aspect ofthe exemplary embodiment, the nickel-iron alloy includes an iron contentbetween about 34% and about 38%. In accordance with yet another aspectof the exemplary embodiment, the nickel-iron alloy includes an ironcontent of about 36% such as Invar®. More specifically, each of firstand second side bars 820 and 822, fin element 825, and first partingsheet 840 are formed from the nickel-iron alloy. End plates 858, 859,862 and 863 may also be formed from the nickel-iron alloy.

In further accordance with an exemplary embodiment, first side bar 820is joined to first end 826 of fin element 825 through a firstnickel-iron alloy bond 870 and second side bar 822 is joined to secondend 828 of fin element 825 through a second nickel-iron alloy bond 871.Also, first end section 845 of first parting sheet 840 is joined tofirst side bar 820 through a third nickel-iron alloy bond 874 whilesecond end section 846 is joined to second side bar 822 through a fourthnickel-iron alloy bond 875. Similarly, first end section 848 of secondparting sheet 842 is joined to first side bar 820 through a fifthnickel-iron alloy bond 880 and second end section 849 is joined tosecond side bar 822 through a sixth nickel-iron alloy bond 881. Further,fin element 825 may be joined to first and second parting sheets 840 and842 through corresponding first and second pluralities of nickel-ironalloy bonds, indicated generally at 890 and 894. Each nickel-iron alloybond 870, 871, 874, 875, 880, 881, 890 and 894 may take the form ofdiffusion bonds in which atoms from each component being joined areshared with the other of the components being joined. Each nickel-ironalloy bond 870, 871, 874, 875, 880, 881, 890 and 894 may also take theform of a joint that is formed through the application of additionalnickel-iron alloy material.

At this point it should be understood that 5000-series aluminum alloyscommonly used in brazed aluminum heat exchangers can be damaged ifexposed to mercury concentration in excess of 0.01 micrograms per normalmeter cubed (μg/Nm3). The use of nickel-iron alloys enables heatexchanger to receive cryogenic gases having a mercury content of greaterthan 0.01 μg/Nm3 without fear of liquid metal embrittlement failure ormercury amalgamation which plague heat exchangers typically constructedof 5000-series aluminum alloys. Further, it should be understood thatthe use of a nickel-iron alloy to construct heat exchanger achieves astronger, more fatigue-resistant unit having a lower coefficient ofthermal expansion than that provided by aluminum. The lower coefficientof thermal expansion greatly increases design allowances for adjacentstream temperature differentials, greatly increases design allowancesfor temperature rate of change, elevates the maximum temperature anddifferential temperature limitations, and allows higher nozzle andpiping loads. Further benefits from the use of a nickel-iron alloyinclude the elimination of, or reduction in cost of, expensivetransition joints. Further, the use of nickel-iron alloy allows for areduction in piping length requirements, a reduced probability of plantshutdown do to leaks, cracks and other issues commonly associated withaluminum heat exchangers, and shorter defrost and start up times.

In accordance with another aspect of an exemplary embodiment, the LNGproduction facility may include a hybrid core-in-shell heat exchangerillustrated generally at 1000 in FIG. 8. Hybrid core-in-shell heatexchanger 1000 may take the place of chillers 33B, 34 and 35 or may beemployed in other systems of the LNG production facility as will becomeevident below. Hybrid core-in-shell heat exchanger 1000 includes avessel 1004 having an interior portion 1006 that is provided with arefrigerant 1008. Refrigerant 1008 is introduced into vessel 1004through a refrigerant inlet 1010 and passed from vessel 1004 through arefrigerant outlet 1012. The particular form of refrigerant employed invessel 1004 may vary.

In further accordance with an exemplary embodiment, hybrid core-in-shellheat exchanger 1000 includes a first exchanger 1020, a second exchanger1024, and a third exchanger 1026. First exchanger 1020 is shown in theform of a tube bundle exchanger 1030 having an inlet 1032 and an outlet1034. Second exchanger 1024 may take the form of a printed circuit heatexchanger (PCHE) 1040 having an inlet 1042 and an outlet 1044. Thirdexchanger 1026 may take the form of a brazed aluminum heat exchanger(BAHX) 1050 having an inlet 1052 and an outlet 1054. Exchangers 1024 and1026 include sections (not separately labeled) that extend aboverefrigerant 1008 by as much as 4-inches (10.1-cm) or more. Exchangers1020, 1024 and 1026 are fluidically isolated from one another yet are ina heat exchange relationship with refrigerant 1008. While described asbeing three-distinct exchanger configurations, it should be understoodthat hybrid core-in-shell heat exchanger 1000 may include exchangershaving two or more exchanger configurations. Further, while shown asincluding three exchangers, the number of exchangers may vary. The useof different exchanger configurations allows for different streamshaving different properties to be passed through a single refrigerantpool. That is, in LNG production, streams may include differentparameters including temperature, pressure, contaminants, such asmercury content and the like, that may not all be compatible with asingle exchanger configuration. The use of various exchangerconfigurations would improve thermal transfer efficiencies for streamscompatible with more efficient heat exchange configurations such as PCHEand BAHX while also allowing non-compatible streams, e.g., streamscontaining amounts of mercury that exceed desireable levels or are atpressures and temperatures that are less compatible with PCHE and BAHXtechnology to pass through the same vessel. In this manner, thehybrid-core-in-shell heat exchanger will improve overall facilityefficiency as well as reduce component costs, maintenance costs,installation costs, and real estate footprint costs associated with theuse of multiple heat exchangers currently needed to accommodate thevarious streams in an LNG production facility.

In one embodiment of the present invention, the LNG production systemscan be simulated on a computer using process simulation software inorder to generate process simulation data in a human-readable form. Inone embodiment, the process simulation data can be in the form of acomputer printout. In another embodiment, the process simulation datacan be displayed on a screen, a monitor, or other viewing device. Thesimulation data can then be used to manipulate the operation of the LNGsystem and/or design the physical layout of an LNG facility. In oneembodiment, the simulation results can be used to design a new LNGfacility and/or revamp or expand an existing facility. In anotherembodiment, the simulation results can be used to optimize the LNGfacility according to one or more operating parameters. Examples ofsuitable software for producing the simulation results include HYSYSTMor Aspen Plus® from Aspen Technology, Inc., and PRO/110 from SimulationSciences Inc.

The preferred forms of the invention described above are to be used asillustration only, and should not be used in a limiting sense tointerpret the scope of the present invention. Modifications to theexemplary embodiments, set forth above, could be readily made by thoseskilled in the art without departing from the spirit of the presentinvention.

While the invention has been described in detail in connection with onlya limited number of embodiments, it should be readily understood thatthe invention is not limited to such disclosed embodiments. Rather, theinvention can be modified to incorporate any number of variations,alterations, substitutions or equivalent arrangements not heretoforedescribed, but which are commensurate with the spirit and scope of theinvention. Additionally, while various embodiments of the invention havebeen described, it is to be understood that aspects of the invention mayinclude only some of the described embodiments. Accordingly, theinvention is not to be seen as limited by the foregoing description, butis only limited by the scope of the appended claims.

What is claimed is:
 1. A method of constructing a plate fin heatexchanger comprising: joining a first side bar formed from a nickel-ironalloy to a first end of a fin element formed from the nickel-iron alloythrough a first nickel-iron alloy bond; and joining a second side barformed from the nickel-iron alloy to a second end of the fin elementthrough a second nickel-iron alloy bond to create a first layer of theplate fin heat exchanger, the fin element defining a fluid passage,wherein the nickel content of the nickel-iron alloy is between about 32%and 42%.
 2. The method of claim 1, wherein joining the first side bar tothe fin element through the first nickel-iron alloy bond includesforming a diffusion bond between the first side bar and the fin element.3. The method of claim 1, wherein joining the second side bar to the finelement through the second nickel-iron alloy bond includes forming adiffusion bond between the second side bar and the fin element.
 4. Themethod of claim 1, further comprising: connecting the first side bar tothe second side bar through a parting sheet formed from the nickel-ironalloy through a third nickel-iron alloy bond and a fourth nickel-ironalloy bond.
 5. The method of claim 4, wherein connecting the first sidebar to the second side bar through a parting sheet through the thirdnickel-iron alloy bond and the fourth nickel-iron alloy bond includesforming a diffusion bond between the first side bar and the partingsheet, and another diffusion bond between the second side bar and theparting sheet.
 6. The method of claim 5, further comprising: joining thefin element and the parting sheet through yet another diffusion bond. 7.The method of claim 1, further comprising: passing a cryogenic fluidhaving a mercury content greater than 0.01 μg/Nm3 through the fluidpassage defined by the fin element.
 8. A hybrid core-in-shell heatexchanger comprising: a vessel including an interior portion configuredto receive a refrigerant; a first exchanger having a first exchangerconfiguration arranged in the interior portion; and a second exchangerhaving a second exchanger configuration arranged in the interior portionand fluidically isolated from the first exchanger, the second exchangerconfiguration being distinct from the first exchanger configuration. 9.The hybrid core-in-shell heat exchanger according to claim 8, furthercomprising: a third exchanger having a third exchanger configurationarranged in the interior portion, the third exchanger being fluidicallyisolated from the first and second exchangers.
 10. The hybridcore-in-shell heat exchanger according to claim 9, wherein the thirdexchanger configuration is distinct from the first and second exchangerconfigurations.
 11. The hybrid core-in-shell heat exchanger according toclaim 8, wherein the first exchanger is a tube bundle exchanger and thesecond exchanger is one of a printed circuit heat exchanger (PCHE) and abrazed aluminum heat exchanger (BAHX).
 12. The hybrid core-in-shell heatexchanger according to claim 8, further comprising: an amount ofrefrigerant contained in the interior portion of the vessel, the amountof refrigerant having a surface portion, wherein at least one of thefirst and second exchangers includes a section that projects above thesurface portion.
 13. The hybrid core-in-shell heat exchanger accordingto claim 12, wherein the section of the one of the first and secondexchangers projects at least 4-inches (10.1-cm) above the surfaceportion.
 14. The hybrid core-in-shell heat exchanger according to claim8, wherein the hybrid core-in-shell heat exchanger forms part of aliquid natural gas (LNG) production.